power system disturbance analysis function

1

POWER SYSTEMDISTURBANCE ANALYSIS

FUNCTION

An analysis of system disturbances provides a wealth of valuable information

regarding power system phenomena and the behavior of protection systems. Expe-

rience can be enhanced and knowledge can be gained from the analysis function. This

book is organized, first, to cover the analysis function and how it can be implemented.

Then, in the following sections, phenomena related to system faults and the clearing

process of faults from the power system are described. Power system phenomena

derived from an analysis of system disturbances are stated. In addition, case studies of

actual system disturbances involving the performance of protection systems for

generators, transformers, overhead transmission lines, cable feeders, and breaker

failures are provided. A section is devoted to problems that enhance an understanding

of the system disturbance analysis function.

Analysis of system disturbance is based on 60-Hz phenomena associated with

power system faults. Therefore, sampling rates of digital fault recorders (DFRs) are

designed to fulfill this requirement. High-frequency power system transient analysis

requires special devices other than conventional DFRs and numerical relays, with

unique requirements different from those of a traditional power system disturbance

analysis function.

Disturbance Analysis for Power Systems, First Edition. Mohamed A. Ibrahim.� 2012 Mohamed A. Ibrahim. Published 2012 by John Wiley & Sons, Inc.

1

COPYRIG

HTED M

ATERIAL

To analyze the performance of protective relaying systems, high-speed digital

fault and disturbance recording devices need to be employed properly. Equipment

can be used for continuous monitoring of the behavior of relaying installed on a

power system during the occurrence of either faults or power swing or switching

operations. The equipment can be used to explain undesired operations and to

assess system performance during correct operation. Analysis of fault records will

help in adapting operating and protection practices and in assuring the reliability

of a bulk power system. The analysis will also help to isolate problems and

incipient failures. In addition, the strategic placement of DFR equipment should

provide adequate coverage of the overall system response to any type of system

fault or wide-area system disturbance. For this reason, DFR applications and

implementation on a bulk power system are mandated by industry standards and

regulations.

A review of DFR records for every operation in a system will help to isolate

incipient difficulties so that corrections can be provided before a serious problem

develops and to provide basic useful information about the performance of the

relaying system. A review of all fault records for disturbances on a system can

enhance the reliability of a relay system. Systematic analysis of disturbances can play

an important role in system blackout avoidance. When they occur during the early

stage of analysis, flagging relay and system problems should be addressed before they

precipitate into wider-area interruption and system blackouts. This can be accom-

plished by analyzing correct operations and finding the causes of incorrect operations.

In addition, it can provide a better assessment of the validity of relay setting

calculations, correct current transformer (CT) and voltage transformer (PT) ratios,

and correct breaker operations. It can also enhance the system restoration process by

providing fault types and locations and a better measure of power quality.

The proposed NERC Reliability Standard PRC-002-02, “Disturbance Monitoring

and Reporting Requirements,” is noted here as a document which ensures that

regional reliability organizations establish requirements for the installation of

disturbance-monitoring equipment and reporting of disturbance data to facilitate

analyses of system events and verification of system models.

1.1 ANALYSIS FUNCTION OF POWER SYSTEM DISTURBANCES

Analysis of power system disturbances can be summarized on the basis of the

following primary functions:

1. The need to view fault data as soon as possible after a fault or disturbance occurs

so as to restore the system safely.

2. The need to design the DFR with a reasonable pre-fault time (5 to 10 cycles) to

capture incipient initiating conditions (e.g., surge arrester spillover).

3. The need to design the DFRwith a long post-fault time, adjustable from 0 to 5 s,

to be able to analyze backup protection clearing times (60 cycles or more) and

2 POWER SYSTEM DISTURBANCE ANALYSIS FUNCTION

limited power system swings (several seconds) following the occurrence of

system disturbances.

4. The need to manipulate the data time base on the DFR record to analyze the

effect of faults.

5. The need, finally, to manipulate the DFR data channels and view only those

selected.

Ideally, the analysis function should be carried out for all relay operations in a

system. The normally cleared events can lead to the discovery of equipment problems

and can also be used as a teaching example for power system behavior and

phenomena. From the analysis function, monthly disturbance analysis reports can

be prepared. In addition, other reports can be generated. The analysis function will

focus primarily on providing answers to the following basic questions:

1. What happened?

2. Why did it happen?

3. What is going to be done about it?

In essence, a sequence-of-events report, or time line, needs to be developed.

Traditionally, a DFR monitors power system voltages and currents, whereas a se-

quence-of-events recorder (SER) monitors relay outputs, breaker and disconnect switch

positions, alarms, relay targets, and relay communication channels.ADFR can integrate

both functions bymonitoring events and analog quantities. The followingare someof the

functions that analysis of DFR records, in conjunction with SER records, can provide:

1. Sequence of operation

2. Fault types

3. Clearing times

4. Reclosing times

5. Relay problems such as:

(a) Failure to trip

(b) Failure to target

(c) Failure to reset

(d) Delayed clearing

6. Communication problems such as:

(a) False operation of blocking schemes during carrier transmission holes

(b) Failure to operate for permissive overreaching transfer trip schemes

during signal loss

7. Circuit breaker problems such as:

(a) Contact arcing

(b) Unequal pole closing

ANALYSIS FUNCTION OF POWER SYSTEM DISTURBANCES 3

(c) Unequal pole opening

(d) Re-strike

(e) Reignition

8. Fault current and voltage magnitudes to confirm a short-circuit model

9. CT saturation

10. Asymmetrical current caused by dc (direct current) offset

11. Fault locations, currently provided by numerically based distance relaying,

can also be provided by DFRs when sufficient analog signals per line are

monitored

1.2 OBJECTIVE OF DFR DISTURBANCE ANALYSIS

Data obtained from DFRs and numerical relaying can be used for continuous

monitoring of the behavior of the relay system and assist in setting operating margins

on critical control and protective apparatus in an electric power system during system

disturbance events such as faults, power swings, and switching operations. Analysis

of the data can have the dual role of explaining undesired operations and assessing

system performance during correct operation.

The primary objective of obtaining and analyzing DFR data is for the purpose of

adapting operating and protection practices as well as control strategies to assure the

security and dependability of the bulk power protection system. The secondary

objective is for the purpose of helping to isolate problems and incipient failures. This

requires a review of all DFR data for every operation, to detect and correct incipient

troubles before they become a serious problem. The ability should exist for remote

interrogation for data analysis and manipulation. Data need to be viewed as soon as

possible after a fault or disturbance occurs. The data time base for the DFR record

should be manipulated for analysis. The ability should exist to manipulate data

channels and view only those of importance. This will ensure that other channels will

not obscure vital data.

It is a good idea to analyze all disturbances in a system, but this may require

additional personnel who may not be available within the utility’s environment.

Indeed, it should be realized that the knowledge gained from analyzing mundane

operationsmay prove to be very valuable. Following are some of the benefits that may

be gained from an analysis of system disturbances:

1. Knowledge of the performance of the relaying system and associated inputs,

outputs, communication system and circuit breakers

2. Root-mean-square (RMS) ground current calculations confirming the power

system model

3. Development of statistics summarizing a fault


4. Optimization of the performance of the relaying system by optimizing the

design process through analysis feedback

5. Identification of power system phenomena of interest to be used as teaching

tools for engineers to enhance their basic technical backgrounds

6. Review of mundane operations that result in successful fault clearing to reveal

valuable power system phenomena and correction of system design and

modeling errors

1.3 DETERMINATION OF POWER SYSTEM EQUIPMENT HEALTHTHROUGH SYSTEM DISTURBANCE ANALYSIS

As mentioned earlier, an analysis of system disturbances can provide feedback

regarding the integrity of power system equipment and associated protection systems.

The following are examples of some of the feedback of analysis results that can be

used to assess equipment health:

1. Detection of excessive capacitor bank outrush currents into close-in faults

requires assessment of current transformer (CT) secondary-connected bur-

dens to reduce overvoltage stress across CT secondary circuits.

2. Detection of circuit breaker (CB) re-striking current during the CB fault

current interruption process requires CB inspection and examination for

possible testing and maintenance.

3. Detection of unequal CB pole closing or opening requires inspection and

examination for possible testing and maintenance of the circuit breaker.

4. Disappearance of third-harmonic current flow in generator neutrals requires

assessment of generator neutrals for the possibility of either an open neutral or

a stator ground fault near the neutral.

5. Determination of undesired relay operation and follow-up analysis can help in

the detection of misapplications of relay settings.

6. Detection and follow-up analysis of undesired relay operation can lead to the

discovery of certain hidden relay failures before the undesired operation can

precipitate into a serious event that can stress the system.

7. Detection of mutual coupling phenomena can help in fine-tuning ground

distance relay settings.

8. Detection of magnetic flux cancellation for CB tripping functions can help in

identifying single failure criteria that can have a serious impact on clearing

future occurrences of system faults.

9. Detection of excessive capacitative voltage transformer (CVT) transients

upon the occurrence or clearing of close-in faults can lead to fine-tuning of

the zone 1 distance relay setting reach.

DETERMINATION OF POWER SYSTEM EQUIPMENT HEALTH 5

10. Thorough system disturbance analysis can lead to optimization of protective

relaying dc schematics.

11. Thorough system disturbance analysis can lead to optimization of protective

relay settings.

12. Thorough system disturbance analysis can lead to detection of surge arrester

spillover that can lead to mitigation of the spill prior to failure.

13. Thorough system disturbance analysis can lead to detection of power system

oscillation, which may require running stability studies to determine the need

to add either out-of-step blocking or tripping relay schemes.

14. Thorough system disturbance analysis can lead to detection of CT saturation,

which may require either reduction of secondary fault currents (by raising the

CT ratio) or reduction of CT-connected burden.

15. Simulation and running of actual system faults, based on disturbance analysis,

using computer-based test sets with the help of the COMTRADE fault current

format can lead to a determination of failed relays and their associated

auxiliary relays.

16. Analysis of multiphase faults caused by lightning strikes can lead to optimi-

zation of transmission tower footing resistance.

17. Determination offlashover at voltage peaks, leading to insulation failure as the

main cause, can provide feedback to correct any insulation design deficiency.

1.4 DESCRIPTION OF DFR EQUIPMENT

Figure 1.1 illustrates the basic subsystem blocks in a digital fault recorder. The analog

input signals are first interfaced to a surge suppression package and sampling filters.

The input current flows through a shunt and is converted to a voltage that is sampled,

converted to digital form by an analog-to-digital (A/D) converter, and then read and

processed by themicroprocessor. Similarly, the input voltage is scaled down to a range

compatible with the A/D range to be converted and then read and processed by the

microprocessor. The A/D has to be checked periodically with sufficient accuracy and

an acceptable A/D conversion resolution of a true 16 bits. Delta–sigma A/D con-

verters implemented on a commercial single-chip design, with built-in autocalibra-

tion capabilities and built-in linear-phase multistage digital decimation and filtering

capability are used for some commercial DFRs to guarantee no aliasing in analog

input-sampled signals. Binary inputs representing various functions within the

substation are also sampled to give a time resolution of about 1ms. The basic

concepts of a DFR function of sampling and storing data whenever a trigger threshold

is exceeded is executed inside the device memory by instruction steps within specific

firmware. RAM memory is used for data and is normally checked on startup of the

DFR device. ROM and PROM are used in the DFR algorithm and software analysis

package and checked periodically bymemory check sum routines. EPROM is used to

store trigger and parameter settings. A programmable digital signal processing


microprocessor is used to perform serial–parallel conversions and extended-precision

adder functions, triggering of recording via various algorithms, and trigger timing

management. The DFR-captured data can be retrieved from a remote location via an

acquisition computer called the master station. The DFR system should be time-

synchronized using an IRIG-B signal from global positioning satellite (GPS) recei-

vers. DFR equipment offers normal communication capability to allow for remote

retrieval of fault and event records, making for immediate disturbance analysis and

reducing the time and cost needed to perform the analysis task.

1.5 INFORMATION REQUIRED FOR THE ANALYSISOF SYSTEM DISTURBANCES

The sequence of events can be derived from an analysis of the fault information that

may be available from several devices. Presently, the problem is that toomanydata are

available from every intelligent electronic device (IED) and the challenge is for relay

and operating engineers to select the most vital data, which need to be analyzed

quickly to restore the affected system safely. A sequence-of-events report may be

developed using some of the following data:

1. Digital fault recorder records and/or oscillograms (if applicable)

2. Sequence-of-event recorder records

I

Microprocessor

RAM

Communication

ROMPowersupply

Digital input

Current &voltage inputs

Contactinputs (DI)V

Shunt

Remote Locations

Parallelport

Serialport

A/D Sample / hold

Signalconditioning

Surge protection& Filters

Samplingclock

IRIG-B

To GPS

receiver

PROMEPROM

HMI

Fig. 1.1 Subsystems of a DFR device.

INFORMATION REQUIRED FOR THE ANALYSIS OF SYSTEM DISTURBANCES 7

3. Relay targets

4. Numerically based protection oscillograph fault records (if applicable)

5. Phasor measurement records

6. System operation logs

7. Event story as created by field personnel

8. SCADA record, indicating system configurations and loading

9. PC-based short-circuit study simulations

10. As-built one-line, ac three-line, elementary, wiring, and logic diagrams

11. Operating procedures

12. Computer logs and customer information

13. Description of system clearances in the event of an operating or technician

error

14. Strip/chart recording or smart IED meters of power system quantities (active

power, reactive power, frequency, voltage, and current)

1.6 SIGNALS TO BE MONITORED BY A FAULT RECORDER

1.6.1 Analog Signals

ADFR will monitor voltages and currents as well as digital inputs from the electrical

power system.Channel assignments to theDFR should considermonitoring sufficient

information to implement the fault location option. This requires the monitoring of

three phase-neutral voltages and three phase currents with an option to either monitor

or calculate the neutral current (In) for each transmission line. In addition, the DFR

should monitor all neutral currents and ground sources at the substation to be able to

validate the short-circuit model for ground faults. Validation of a short-circuit model

for phase faults is difficult to accomplish, due to the effect of loading, which is

normally not factored in a steady-state quasi-short-circuit study simulation.

The analog channels are normally configurable as voltage or current inputs. The

phase-to-neutral voltage inputs may be scaled for about 66.4V, with a range of 0 to

250V RMS, allowing a margin of more than 2 pu (per unit) overvoltage. Current

inputs may be scaled for 5ARMS (nominal load current) and at least 100A full-scale

input using calibrated shunts. The thermal duty can be rated at least 10A RMS

continuous and at least 200A RMS short time for 2s. Monitoring a generator dc field

current can provide valuable educational information about negative-sequence

double-frequency-induced rotor current during unbalanced system faults. In addition,

monitoring a generator dc field will reveal the 60-Hz induced rotor current during

inadvertent energization of generator incidents. Both phenomena are illustrated

herein through applicable generator case studies.

Dedicated sensors with over, under, and rate-of-change value settings were used

for traditional (conventional) oscillographs. DFRs can also be programmed for


each analog channel for over, under, or rate-of-change settings. Additional sensors

may include positive-sequence current or voltage, negative-sequence current or

voltage, zero-sequence current or voltage, frequency transducers rate of change of

impedance during a power system swing (long-term rate of change), and total harmonic

distortion.

Following is a list of typical analog channels monitored at the substation level:

. Phase-to-neutral voltages

. Line phase and neutral currents

. Transformer neutral currents

. Transformer tertiary currents

. Transformer polarizing currents (sum of more than one current)

. Capacitor currents (phase and neutral)

. Shunt reactor currents

. Transformer high- and low-side currents

. Zero-sequence voltages

. Bus voltages

. Generator neutral voltages

. Generator fields

. Generator currents

. Generator phase-to-neutral voltages

Monitoring of tertiary (3I0) current by aDFRmayhelp in the classificationof ground

faults. TheCTs for all the phases are paralleled to collect ground current (3I0) and filter

out any loading currents (the sum of balanced positive-sequence currents¼ 0). For

breaker-and-one-half substation configuration, monitoring of the middle breaker

ground current can provide valuable information for circuit breaker maintenance

by showing the last breaker of the two that will interrupt the fault current. In addition,

determinationofwhich of the two line breakers is exhibiting a re-strike during the fault-

clearing process can be accomplished.

1.6.2 Event (Digital or Binary) Inputs and Outputs

Most DFR systems provide means for event recording. This may be status change

(closing or opening) of an auxiliary contact associated with a circuit breaker or a

disconnect switch operation or the presence of voltage at a control circuit node, which

would indicate that a certain control logic function was performed. Examples of

events are positions for circuit breakers; disconnect switches, dc presence for control

circuits, relays, auxiliary relays, lockout relays, and protection communication

signals. Event recording can also be performed by dedicated SERs in the form of

stand-alone packages or as part of other systems, such as remote terminals for SCADA

systems. Most SER systems are designed with a typical 1-ms resolution time.

SIGNALS TO BE MONITORED BY A FAULT RECORDER 9

1.7 DFR TRIGGER SETTINGSOFMONITORED VOLTAGES AND CURRENTS

In older oscillograph equipment, recording was generally begun using dedicated start

sensors to capture fault records. Delta tertiary zero-sequence currents and transformer

neutral currents were commonly used to sense ground faults. Undervoltage sensors

were also used at key voltage points within the substation, together with an operation

limiter, to sense phase faults. Dedicated negative-sequence sensors were also used to

trigger the device for unbalanced faults.

The present state-of-the-art DFR is designed with trigger algorithms that are

capable of detecting over, under, rate-of-change, and swing conditions for each analog

input channel. The trigger algorithm provides concurrent user selectivity for step

change, ramp change, and oscillatory conditions. The DFR is normally triggered to

capture a record by all analog channels and selected binary inputs. The DFRmonitors

for line faults three phase-to-neutral voltages and three phase and neutral currents for

each line connected at the substation. Phase undervoltage and phase overcurrents will

trigger the DFR for phase line faults, and neutral currents will trigger for ground line

faults. One analog trigger is sufficient to capture a DFR record.

In addition, triggering can be initiated using positive-, negative-, and zero-

sequence symmetrical components as a supplement for shunt faults and as a main

trigger for series imbalance, such as open phase. A frequency computation from a bus

voltage can also trigger a frequency deviation. Total harmonic distortion and

individual harmonic distortion for a specific frequency can also be programmed to

trigger a DFR to provide an analysis of power quality. Impedance can also be

calculated and used to trigger a DFR. Power swing amplitude for voltage, current, and

active and reactive power, as well as oscillation frequency and rate of change of

impedance, can also be used to trigger a DFR. In addition, selected digital inputs can

be used to capture a record: for example, emergency shutdown lockout relays, which

can be energized by many abnormal conditions at a generating plant.

Manual triggering is also provided to test the data capture and output function of a

DFR.Themanual triggermaybehardwired or software based,with anoption for remote

acquisition from a master station location. The DFR can also be configured to have a

very slow scan to capture long-term events such as power system oscillations or out-of-

step conditions. Each trigger function is user programmable with an individual dual-

mode limiter function. This function prevents excessive recording both in case a trigger

condition persists for an extended period of time and in case a “chattering” trigger

should occur. The operation limiter feature will restrict data recording to a selectable

length in the event of a continuous long-term trigger condition. An example is the use of

undervoltage to trigger the capture of a record for phase faults on a system. Since all

analog-monitored channels will be used as triggers, this voltage may be associated with

a transmission line. When the line is removed from service during a scheduled outage,

the undervoltage sensorwill trigger theDFR to capture a record. However, ameanmust

be established to limit the length of the record since triggering will continue as long as

the line is out of service. It should be noted that if phase overcurrent is used to trigger a

DFR for faults, the operation limiter feature is not required.


The pre-trigger is normally set at 5 cycles, with an adjustable range from 1 to 10

cycles of the power system frequency. The post-fault range is normally set at 1 s, with

an adjustable range from 1 to 5 s. A DFR sensor setting must be established carefully,

similar to a relay setting. Every channel should trigger and the DFR sensors should be

set to record the minimum fault currents. The DFR-monitored phase currents can be

set at a typical overcurrent threshold of 150% of nominal currents. This setting should

also be above themaximum emergency loading. TheDFR-monitored neutral currents

can be set at 20% abovemaximum loading. DFR-monitored voltage channels can also

be set at an overvoltage threshold of 110% of nominal values.

1.8 DFR AND NUMERICAL RELAY SAMPLING RATEAND FREQUENCY RESPONSE

Obsolete oscillograph devices produce oscillograms having a frequency response of

about 1000 to 1200Hz. Newer DFR frequency responses can reach a much higher

value than 1200Hz and normally are a function of sampling rate and the device low-

pass filter interface. To avoid aliasing of the analog signal sampled, a low-pass

sampling filter is used in numerical relays. The filter blocks any frequency that is

higher than half the sampling rate, and thus affects the relay oscillograph record when

based on filtered samples. For example, a numerical relay with a sampling rate of

20 samples/cycle will have a frequency response of 600Hz (¼ 0.5� 20� 60),

whereas a DFR with a sampling rate of 64 samples/cycle will have a frequency

response of 1920Hz (¼ 0.5� 64� 60).

A DFR can be specified to have a typically higher sampling rate than that used in

numerical relaying. Sampling rates in most DFRs are programmable and range from

64 samples/cycle to 320 samples/cycle, depending on the manufacturer. Sixty-four

samples/cycle is a typical sampling rate, and it is more than enough to provide

sufficient resolution to verify 60-Hz short-circuit study simulation models. The DFR

record length is normally set at 1 s, with the number of pre-fault cycles being

programmable and normally set at 5 cycles with a range of 1 to 10 cycles.

A DFR sampling rate of 5760 samples/s per channel can also be defined as

96 samples/cycle (¼ 5760/60) at 60Hz. The sampling rate can also be defined in

terms of electrical degrees as 360�/96¼ 1 sample every 3.75�. The sampling rate can

also be written as 1 sample every 173.6ms (¼ 16.666ms/96).

1.9 OSCILLOGRAPHY FAULT RECORDS GENERATEDBY NUMERICAL RELAYING

The multifunction numerical relays used for protection also provide valuable

oscillograph fault records. Multifunction numerical relays used to protect generators

and transformers have benefited power system disturbance monitoring functions by

providing valuable oscillograph fault records for postmortem analysis. Transformer

OSCILLOGRAPHY FAULT RECORDS GENERATED BY NUMERICAL RELAYING 11

high-, low-, and tertiary-side currents as well as generator neutral- and system-side

currents are normally not monitored by a substation DFR, due to the device’s limited

number of analog channels. Built-in numerical relaying capability can assist in the

analysis of power system disturbances. The information contained in these records

can be used to identify the type of system testing needed to identify the cause of the

tripping. This will speed up the return of equipment to service. For example, it will

provide the necessary data to keep a generatingmachine either off-line for testing and

inspection, when necessary, after an electrical tripping event, or to return the unit to

service with minimum delay. Oscillographic monitoring of generators provides

invaluable information that will enhance a utility’s decision-making process. In

addition, numerical relay fault records provide fault type and fault location to assist in

fast restoration of faulted transmission lines.

Numerical relays are designed with antialiasing filters, which are required to

prevent frequency folding and aliasing of multiples of the sampling rate from

appearing with the original samples, which represent the true signal. Antialiasing

filters will fulfill theNyquist criterion, which states that frequencies above one-half of

the sampling rate must be removed to avoid aliasing error in the signal sampled.

Sampling of digital channels has a normal scanning rate that permits at least 1ms of

resolution time.

1.10 INTEGRATION AND COORDINATION OF DATA COLLECTEDFROM INTELLIGENT ELECTRONIC DEVICES

DFRs, revenuemetering, and numerical relaying IEDs have the ability to transmit fault

records and events to designated locations for further analysis. One of the challenges

for power system analysis is to coordinate the overwhelming amount of data gathered

by IEDs used for protection, fault recorders, meters, and SERs. There exist software

and hardware systems that can collect and analyze the IEDs furnished by various

manufacturers using different data formats to select the most relevant and vital data

required for the analysis. However, the use of a standard format such as COMTRADE

can help to promote remote collection of data using sophisticated software.

Many difficulties were encountered during analysis of a major system blackout in

2003, due to the fact that many fault records had time stamps that were difficult to

correlate. To avoid similar problems in the future, it is nowmandated that time stamps

be synchronized. This can be accomplished by time synchronization of all IEDs in the

bulk power system using an IRIG-B signal from GPS receivers.

1.11 DFR SOFTWARE ANALYSIS PACKAGES

Most DFRs are equipped with software packages that can provide various system

calculations and manipulations to simplify the analysis functions. Some of the

software analysis packages currently available are described below.


1.11.1 Phasor Analysis

Phasor analysis helps in assessing the quality of a three-phase system in terms of

voltage or current magnitude and phasor relationships and in understanding power

system phenomena. When one phase is selected as a reference, the remaining phases

will then be plottedwith their angles shown relative to the reference for a known phase

sequence. Phasors can then be shown with their magnitudes and arguments (polar

form), so that three-phase analysis can then be executed to calculate active power

(MW), reactive power (MVAR), and current and voltage phasors.

Case Study 1.1: Use of DFR Phasor Analysis Software Figure 1.2 shows an

independent power producer (IPP) connected to a bulk power system through the use of

115-kV line L1 as a plant startup ac source. The cogeneration facility at plant Ywas on a

reserve shutdown status, with the understanding that the 115-kV system is the sole source

for the IPPstation service facility.AphaseB to-ground (B-g) fault occurredon the230-kV

bus1atsubstationX,with theDFR-monitoredvoltagesandcurrentsshowninFig.1.2.The

DFR record shown in Fig. 1.3 at substation X reveals that the zero-sequence current

contribution traceL1-In fromtheplantYunit transformer to the faultwas interruptedwhen

115-kVCBA1opened.However, immediately following theCBA1opening, three-phase

balanced voltage traces L1-Va-n, L1-Vb-n, and L1-Vc-n appeared on 115-kV line L1 at

substation X. The voltages stayed on the line for 3.5 cycles, followed by an opening

transient. It should be noted that as according to the design of the IPP facility and the

DFR

DFR

A1

X

L1

G

B1

G Possible emergencygenerator

80 MWCT unit

L1 -In

Substation X

IPP plant Y

Va-nL1 -L1 -Vb-n

Vc-nL1 -

115 kV

Station ServiceTransf.

100 MVA Transf.13.8/115 kV

B1

Auto TR. 120 MVA

230/115/13.8 kV

B-g fault230 kV Bus 1

230 kV Bus 2

Fig. 1.2 System one-line diagram showing DFR-monitored voltages and currents.

DFR SOFTWARE ANALYSIS PACKAGES 13

operating agreement with the utility, this line voltage should be zero (a deenergized

system). The removal of the line voltages coincided with the direct transfer trip signal,

which was generated by the opening of CBA1 and sent over the fiber optic system to trip

CBB1 at plant Y. This featurewas incorporated in the design to guarantee the opening of

the interconnection CB B1 following an accidental opening of CB A1 at substation X.

Hence, itwill facilitate resynchronization of the IPPunits using circuit breakers at plantY.

The DFR records were analyzed further to make sure that no distribution source at

the IPP facility was placed in parallel with the transmission system. An off-line DFR

software phasor analysis programwas used to investigate the source of this linevoltage.

As shown in Fig. 1.3, the depressed B phase voltage was back to normal after the

opening of CBA1, whereas phases A and C revealed a slight phase shift at the opening

moment. Figure 1.4 illustrates the pre-fault voltages,which are balanced (120� between

Fig. 1.4 115-kV voltage phasor diagram for the pre-fault condition.

Fig. 1.3 DFR record for the 115-kV line L1 voltages and ground current during clearing

of the 230-kV B-g fault.


phases)with an approximate average phase-to-neutralmagnitudevalueof 67.5 kVand a

period indicating 60-Hz system frequency. As shown in Fig. 1.5, analysis of the line L1

voltages following the line trip at substation X revealed an unbalanced voltage with an

approximate average magnitude value of 56.5 kVand a slightly greater period for this

line voltage than the nominal 60Hz. Therefore, the frequency of this voltage is lower

than 60Hz and is calculated to be about 51Hz. The lower magnitude of voltage and

frequencymay imply that the source is a small emergency generator thatwas connected

at the IPP plant auxiliary bus prior to the phase B-g line fault. The source appears to be

very weak, with no significant positive-sequence contribution that has any effect on the

contribution to the initial B-g fault on the 230-kV bus and the zero-sequence current

flow on the 115-kV system during the fault.

1.11.2 RMS Calculation

The root-mean-square (RMS) value of continuous periodic current signals when

sampled N times per cycle is defined as

IRMS ¼ffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffi1

N

XNk¼1

ðikÞ2vuut ð1Þ

where IRMS is the root-mean-square current value,N the number of samples per cycle,

and ik the data points sampled.

One of the uses for RMS values of monitored DFR signals is to confirm the power

systemmodel. This can be done by using fault type and fault location to run a software

package to simulate faults, using short-circuit studies and comparing the results

calculated with the measured (via calculations) DFR RMS values recorded. RMS

calculations can be executed for all recorded signals through the entire record by

positioning two cursors separated by a fixed 1-cycle length (16.666ms). The RMS

calculation algorithm grabs the digital sampled data within the DFR memory

Fig. 1.5 115-kV voltage phasor diagram for the post-fault condition.


(between the two cursors) and executes an accurate RMS software calculation. This

can be done by using one of the phasor estimation techniques, depending on the DFR

manufacturer. One technique could be discrete Fourier transform (DFT) formula (1)

with the algorithmwindow defined as the 60-Hz period, which is equal to the distance

between the two cursors. The results are posted as a part of the record in primary

values. Figure 1.3 illustrates a DFR record with the RMS currents calculated for the

1-cycle-width cursors shown at the right side of the record. For phase-to-ground

faults, RMS values for ground currents can then be used to validate the short-circuit

model by comparing the RMS calculated from the DFR record versus the RMS values

obtained from short-circuit study simulations.

Example 1.1: RMS Calculation of Continuous Periodic Current Signals

When Sampled Eight Times per Cycle Let

iðtÞ ¼ 10 sin vt ð2Þ

Then the RMS value is

Ipeakffiffiffi2

p ¼ 10ffiffiffi2

p ¼ 7:07 A ð3Þ

Assume that the analog current was sampled eight times per cycle (Table 1.1).

Using equation (2), the samples can first be deduced and digital RMS formula (1) can

be applied:

IRMS ¼ffiffi1

8

q X80

ðikÞ2 ¼ffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffi0þ 50þ 100þ 50þ 0þ 50þ 100þ 50

8

r¼

ffiffiffiffiffiffiffiffi400

8

r¼ 7:07 A

which is the same result as that obtained in equation (3).

T A B L E 1.1 Data for Current Sampled Eight Times per Cycle

Sample vt Sample Value (10 sin vt) (ik)2

1 0� 10 sin 0� ¼ 0 0

2 45� 10 sin 45� ¼ 10/ffiffiffi2

p50

3 90� 10 sin 90� ¼ 10 100

4 135� 10 sin 135� ¼ 10/ffiffiffi2

p50

5 180� 10 sin 180� ¼ 0 0

6 225� 10 sin 235� ¼ 10/ffiffiffi2

p50

7 270� 10 sin 270� ¼�10 100

8 315� 10 sin 315� ¼�10/ffiffiffi2

p50


When Sampled Four Times Per Cycle Assume that the analog current was

sampled four times per cycle (Table 1.2). Using equation (2), the samples can first

be deduced and digital RMS formula (1) can then be applied. It should be noted that

this sampling rate is above the Nyquist criterion of� 2 of the frequency of the signal

needed (60Hz):

IRMS ¼ffiffi1

8

q X40

ðikÞ2 ¼ffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffi0þ 100þ 0þ 100

4

r¼

ffiffiffiffiffi50

p¼ 7:07 A

which is the same result as that obtained above.

1.11.3 Calculation of Active and Reactive Powers

Calculation of the active and reactive power is very useful for a power plot during

power system oscillation to determine the oscillation frequency. Generator or trans-

mission-line active power flows can be calculated using the active power formula,

P ¼ ffiffiffi3

pV � I cos f, and then plotted as a function of time. Generator reactive power

flows can be calculated using the formula Q ¼ ffiffiffi3

pV � I sin f, and then plotted as a

function of time. In addition, reactive power flow can be recorded for further analysis.

Generator out-of-step or oscillation conditions can then be confirmed by analyzing

active and reactive power plots. For faults near generator terminals, plotting reactive

powers can illustrate the sudden change of power factor from load to fault condition

where the phase angle for load is near 30� and greater than 60� for faults.

1.11.4 Data Display Manipulation

All DFR records can be displayed for analysis on computer screens for true RMS

calculation, phasor analysis, harmonic analysis, and trace manipulation, including

expanding, compressing, selection, and movement. Any user-selected group of

channels up to the total traces involved in a given disturbance can be displayed.

The DFR start sensors or triggers will start the data storage process of all inputs.

Software packages will provide support for data display and the analysis required.

This software will include conversion of data to a COMTRADE format, allowing the

records to be used for testing, troubleshooting, and verification purposes. In addition

T A B L E 1.2 Data for Current Sampled Four Times per Cycle

Sample (vt) Sample Value (10 sin vt) (ik)2

1 0� 10 sin 0� ¼ 0 0

2 90� 10 sin 90� ¼ 10 100

3 180� 10 sin 180� ¼ 0 0

4 270� 10 sin 270� ¼�10 100


to all software analysis functions noted earlier, the following functions are also

normally available:

1. Immediate display of all abnormal channels, with automatic separation

between traces

2. Selection and relocation of traces during record display

3. Overlay of certain traces for balanced display of a three-phase system

4. Manipulation of traces for compression, expansion, or change of amplitude

5. Grouping of certain channels to provide easy display (e.g., three-phase-to-

neutral voltages and three-phase and neutral currents for each transmission line

monitored).

6. Synchronization of fault records at one end of the line with records obtained at

the remote end of the line (can be used to execute double-ended fault location

algorithms, if required)

Case Study 1.2: Use of DFR Data Display Manipulation Figure 1.6 shows a

one-line diagram for a 115-kV system connecting substations Y and Z and the DFR

signals monitored at substation Y. An apparent lightning strike caused a three-phase

fault on 115-kV line L1. Cursor X shown in Fig. 1.7 makes the fault appear to be a

simultaneous three-phase fault that lasted for 5.5 cycles. Phase A clears at point a,

followed by phase B clearing at point b after 120�, followed by phase C at point c after

120�, thus confirming the correct phase sequence as ABC. However, a lightning

creation mechanism of a simultaneous three-phase fault requires further analysis.

DFR technology permits expantion of the recorded traces in the direction of both

the time and magnitude axes. The expansion of the time axis of 115-kV line L1 three-

phase and neutral current traces, shown in Fig. 1.8, reveals that the fault started as

an apparent direct lightning hit on phasesA andB, as indicated by cursor a, causing an

A-B-g fault and then evolving into a three-phase-to-ground fault, as indicated by

cursor b 0.7ms after cursor a.

Therefore, the incident can be explained as a direct lightning hit on phases A and B

where the fault current caused by the lightning stroke went to ground via the tower

footing resistance. The voltage buildup across the tower footing resistance caused a

back flashover from the ground to phase C about 0.7ms later.

B

DFR

DFR

A1

A2

A3

L1-Va-n

L1-Vb-n

L1-Vc-n

115 kV

115 kV

Line L1

3-phase fault

X

L1-Ia

L1-Ib

L1-Ic

L1-In

Substation ZSubstation Y

Fig. 1.6 One-line diagram showing DFR-monitored 115-kV voltages and currents.


1.11.5 Fault Location

Fault Location Using a DFR Record and PC-Based Short-Circuit SimulationSoftware For bolted faults (fault resistance¼ 0) with symmetrical currents, the

fault location can be determined by sliding the fault application point on the faulted

line using short-circuit simulation studies until a result match is established between

DFR-recorded versus calculated currents and voltages.

Fault Location Using a DFR Record and a Software Package When a

transmission line’s three voltages and four currents are monitored by a DFR data

Fig. 1.8 Substation Y DFR time-expanded record for currents confirming a phase A-B-g

fault, then evolving into a three-phase-to-ground fault.

Fig. 1.7 Substation YDFR record for voltages and currents revealing a simultaneous three-

phase fault.


acquisition unit, a fault location function can be performed using either a single- or a

double-ended fault location algorithm residing within the DFR. A fault classification

subroutine is needed to provide the correct faulted impedance loop. This is one of the

six loops that cover all types of 10-line faults. A software subroutine is also needed to

determine the faulted line so that the faulted-line impedance can be calculated

automatically and sent to operating or control centers. Presently, this function is

also provided by dedicated numerical distance line protection.

Fault Location Using Numerical Relaying Numerical relaying provides very

accurate fault location results as a part of event record output from the relay.

Numerical relaying has provided good results for fault location since its inception

in the late 1980s. Some DFR and numerical relay ocillograph records provide means

to synchronize data obtained from both ends of a faulted line to executemore accurate

double-ended fault location algorithms.

1.11.6 Harmonic Analysis of a Power System

ADFR can be used as a power quality instrument by recording the harmonic and total

harmonic distortion (THD) profiles of voltage and current waveforms. A DFR can

perform harmonic analyses on recorded currents and voltages and use the information

to measure trends over time or to compare harmonic distortion at different locations.

Depending on the manufacturer and the type of interface filtering, most DFRs can

calculate fromdc up to the twenty-fourth harmonic of currents and voltages. Harmonic

analysis and THD profiles can be used for power quality monitoring of various

monitored power sources and to assess the harmonic sources for removal purposes.

1.11.7 Symmetrical Components Analysis

Symmetrical components analysis software can be used on DFR-recorded currents

and voltages to obtain positive-, negative-, and zero-sequence components. During

ground faults the zero-sequence currents can be used for the validation of short-circuit

60-Hz models. The phase currents are not suitable for use, due to the effect of the

positive-sequence component of load flow. Current or voltage sequence components

can trigger a DFR to capture certain fault records. In addition, the current and voltage

sequence components can help in studying the response of special relaying elements

to system faults. This type of analysis can also be used to confirm the occurrence

of low-grade equipment faults. Case Study 5.7 is a postmortem analysis of sampled

DFR records for the transformer fault sources. A symmetrical component transform

operation was performed on 138-kV system contributions to a transformer ground

fault, indicating the presence of positive-, negative-, and zero-sequence current

components during the fault, thus confirming the occurrence of a winding ground

fault. Pre- and post-fault analyses revealed only positive-sequence currents.

This matches the off-line simulation for the strength of the 138-kV system behind

the transformer.


1.12 VERIFICATION OF DFR ACCURACY IN MONITORINGSUBSTATION GROUND CURRENTS

For substations where all ground currents from all transmission lines and trans-

formers zero-sequence sources are monitored by a DFR, confidence can be

established for the correct connection and scaling of all DFR currents. This can

be accomplished by applying Kirchhoff’s first law for a faulted line. This method is

applicable to symmetrical fault currents that contain no dc offsets. This is normally

the casewhen the fault incident point is at the voltage peak, indicating the slow fault-

creation mechanism that normally accompanies insulation failure. In this case, the

RMS current calculated by the DFR software is sufficiently accurate to use this

method to verify DFR recorded signal accuracy. All zero-sequence sources

monitored will be selected in one record, and the 1-cycle RMS calculation window

will be selected for the entire record so that results are obtained at the same time. The

following case study illustrates a simple procedure that can be implemented to

verify DFR accuracy.

Case Study 1.3: Verification of DFR Accuracy Based on the one-line diagram

for substation X in Fig. 1.9, and since all ground currents (zero-sequence) feeding the

C-g fault from transmission lines and autotransformer tertiary currents are monitored

by a DFR, the following check can be made to verify the accuracy of the DFR

recording of the currents monitored.

Figure 1.9 shows the DFR-monitored ground currents and the transformer delta

tertiary. Figure 1.10 shows the 230- and 115-kV systems around substation Xwhere a

phase-to-ground fault occurred on line L1. The DFR record in Fig. 1.11 reveals all

Substation X

115 kV

115 kV

DFR

L3

L4

X

C-gFault

L2-In

L1-InTR. T1

Tr. T2

T1-Iter.

T2-Iter.

L3-In

L4-In

115 kV

Substation Y

230 kV

DFRDFR

L2

DFR

DFRDFR

230 kV

L1

Fig. 1.9 Substation X one-line diagram showing DFR-monitored currents.

VERIFICATION OF DFR ACCURACY IN MONITORING SUBSTATION 21

Fig. 1.11 Substation X DFR record for ground currents showing the one-cycle RMS

calculation.

Substation X

115 kV

L1

XC-g

Fault

TR. T1

Tr. T2

Substation Y 115 kV

L2

L3

L4

230 kV

230 kV

L2 -In

L3 -In

L4 -InL1 -In

T2 -Iter.

T1 -Iter.

Fig. 1.10 One-line diagram showing ground current flows to the C-g fault.


ground current sources feeding into the line L1 C-g fault. The sources from substation

X are: 230-kV line L3, 230-kV line L4, 115-kV line L1, 115-kV line L2, and

transformer T1 and T2 delta tertiary windings. The DFR shown in Fig. 1.11 also

reveals symmetric fault currents, which results in accurate RMS current calculations

by the DFR software package.

From symmetrical components analysis, the following equation is satisfied if all

currents are in per-unit (pu) values on a common base, which in this case is

100MVA:

InðL1Þ ¼ InðL2Þþ InðL3Þþ InðL4Þþ IterðT1Þþ IterðT2Þ ð1Þ

At the beginning of the fault, while the line is still fed from substation X, DFR RMS

calculation routine can be executed for a one cycle windowwhich is positioned about

one cycle from fault initiation. RMS currents are then calculated and the results

become part of theDFR record. The currents shown at the right side of theDFR record

in Fig. 1.11 are as follows:

L1-In¼ InðL1Þ ¼ 5440 A




T1-Iter ¼ IterðT1Þ ¼ 1040 A

T2-Iter ¼ IterðT2Þ ¼ 1040 A

To convert all these currents to pu values, we need to define the base current for 230-

and 115-kV lines as well as the 13.8-kV delta tertiary currents:

Ibaseð115 kVÞ ¼ 100� 106ffiffiffi3

p � 115� 103¼ 502 A


p � 230� 103¼ 251 A

Ibaseð13:8 kVÞ ¼ 100� 106

3� 13:8� 103¼ 2415 A

The 13.8-kV base current is calculated using a dividing factor of 3 for phase current

that flows inside the delta and is equal to Iline=ffiffiffi3

p.

Ipu ¼ I

Ibase

where I is the DFR recorded current. Therefore, currents in pu are

VERIFICATION OF DFR ACCURACY IN MONITORING SUBSTATION 23

InðL1Þ ¼ 5440

502¼ 10:83 pu

InðL2Þ ¼ 600

502¼ 1:2 pu

InðL3Þ ¼ 1110

251¼ 4:42 pu

InðL4Þ ¼ 1200

251¼ 4:78 pu

IterðT1Þ ¼ 1040

2415:4¼ 0:431 pu

IterðT2Þ ¼ 1040

2415:4¼ 0:4:31 pu

Substituting these values in equation (1) gives us

right-hand side ðRHSÞ ¼ 10:83 pu

left-hand side ðLHSÞ ¼ 1:2þ 4:42þ 4:78þ 0:431þ 0:431 ¼ 11:26 pu

% error ¼ current difference in pu

the smaller of the two� 100

¼ LHS�RHS


¼ 11:26�10:83

10:83� 100 ¼ 4:2% < 10% O:K:

It can then be concluded that the DFR accuracy of recording is acceptable.

1.13 USING DFR RECORDS TO VALIDATE POWER SYSTEMSHORT-CIRCUIT STUDY MODELS

DFR and numerical relay event records can be used to validate 60-Hz power system

models. During ground faults the ground (neutral) 3I0 currents and the faulted phase-

to-neutral voltage can be used for validation of the short-circuit models. It is not

recommended that phase currents be used, due to the effect of the positive-sequence

component of the load flow. The DFR recorded will reflect the effect of load flow;

however, quasi-steady-state short-circuit study will not reflect the same effect. Phase-

to-phase and three-phase fault cases can be used when the positive-sequence

measured current I1 is calculated and the effect of load flow is removed. When the

fault incident point is at the voltage peak, the fault currents will be symmetrical,


containing no dc offset. The resulting currents from all the sources can then be used to

validate the short-circuit model. This can be accomplished by comparing the RMS

values calculated from the DFR record versus the RMS values obtained from the

short-circuit study simulation.

For solid ground faults, the only unknown that must be simulated for model

validation is fault location. The unknown fault location point can be solved by sliding

the fault on the faulted line until amatch is established between the simulated fault and

the DFR analog values recorded. For high-resistance (tree) ground faults where the

fault location is known, the fault can be simulated at the known location while varying

the fault resistance values until a match is established between the simulated fault and

the DFR analog values recorded.

Case Study 1.4: Bolted 115-kV Phase-to-Ground Bus Fault This case study

is ideal for verification of the power system short-circuit model. This is due to the

known fault location and the symmetrical nature of the fault current. The solid phase

B-g fault was caused by the failure of a station post insulator, which supports a

disconnect switch during heavy rain. Monitoring of all ground current sources and

neutral currents at substation X will allow verification of the modeling of the power

system. In this case study, autotransformer T9 and T10 ground currents on the 115-kV

bus are notmonitored by the DFR, thus allowing only a partial assessment to bemade.

Figure 1.12 is a symbolic substation X one-line diagram showing the DFRmonitored

and unmonitored neutral lines and transformer currents.

At the beginning of the disturbance the B-g fault was symmetrical, containing no

dc offset. This portion of the fault duration can therefore be used to verify the

accuracy of the modeling of the generators and their step-up transformers. In

addition, partial verification for the other recorded sources of the ground fault can

also be verified. This can be done by comparing the DFR RMS current values

measured to the values calculated from a short-circuit simulation study. All ground

current sources can be compared to the 115-kV bus fault, with the exception of the

XSubstation X

115 kV Bus

T4

T1

T3

T2

T9**

BK7

BK8

To 230 kV

L2

L3

L1115 kV

115 kV

Bus L-g fault

115 kVL2-In*

L3-In*

L1-In*

T4-In*

T1-In*

T3-In*

T2-In*

BK8-In*

BK7-In*

T10**

* DFR Monitored neutral current

** Not monitored by the DFR

Fig. 1.12 Substation X symbolic one-line diagram showing DFR-monitored currents.

USING DFR RECORDS TO VALIDATE POWER SYSTEM 25

T9 and T10 contributions, which are not monitored by the DFR, due to the lack of

available DFR analog channels.

Figure 1.13 shows the DFR record for some of the neutral current contributions to

the 115-kV bus fault. In addition, the figure reveals the RMS values of these fault

currents as calculated by the DFR calculation software for a 1-cycle data window

starting 1 cycle after initiation of the fault. Ground currents are not affected by load

flowand can therefore be used to compare simulated versus actual fault current values.

A solid phase-to-ground bus fault was then simulated in the short-circuit study

program to provide calculated system values which could then be compared with the

DFR record. The study provides a total 115-kVbus ground fault of 44.59 kA, as shown

in Fig. 1.14. Table 1.3 shows the RMS values for the measured and calculated current

values and the comparison needed to ascertain the validity of the model. The analysis

also defines an error formula to obtain the accuracy of the system model. The errors

should not exceed�10% (�15% is also acceptable for special cases). This threshold

is considered reasonable to accommodate errors in the primary sensing equipment

(CTs and PTs) and in the DFR equipment and the parameters used to calculate

impedances for short-circuit study simulations. Based on these criteria, the neutral

current of unit transformer BK8 trace BK8-In shown in Fig. 1.13 has an error of 2%,

which confirms that themodeling in the short-circuit study of the generating units and

their associated step-up transformer is correct. In addition, the maximum error for the

Fig. 1.13 DFR record for ground currents showing the one-cycle RMS calculation window.


feeders is 7.7% for the line L3 contribution to the fault, which is less than the error

threshold and therefore is also acceptable.

Case Study 1.5: High-Resistance 230-kV Phase-to-Ground Line Fault This

case study is not an ideal case for verification of the power system short-circuit model,

due to the resistive nature of the fault and the unknown fault location. The high-

resistance C-g fault occurred on 230-kV circuit line L1, as shown in Fig. 1.15. The

fault was caused by a tree that was located where arcing was observed between the

conductor and the tree. The fault was therefore (luckily) located at about 94% of line

1349 A998 A

913 A

4612 A

4612 A

5352 A

4612 A

X

5475 A

5653 A

4612 A

5468 A

T10

44594 ASubstation X

115 kV Bus

T4

T1

T3

T2

T9

BK7

BK8

To 230 kV

L2

L3

L1115 kV

115 kV

Bus L-g fault

115 kV

Fig. 1.14 Short-circuit study simulation producing zero-sequence currents (3I0) for a solid

115-kV L-g bus fault.

T A B L E 1.3 Comparison Between Measured and Calculated Fault Currents

Feeders

Contributing to

the Bus Fault

DFR RMS

Values Measured

RMS Values

Calculated from the

Short-Circuit Study

Error

ValuesaPercent

Errorb

L1-In 1341A 1349A �8 �0.6

L2-In 1028A 998A 30 3.0

L3-In 983A 913A 70 7.7

T1-In 4477A 4612A �135 �3

T2-In 4424A 4612A �188 �4.25

T3-In 5168A 5352A �184 �3.6

T4-In 4685A 4612A 73 1.6

BK7-In 5501A 5653A �152 �2.7

BK8-In 5781A 5665A 116 2.0

T9-In Not monitored 5475A

T10-In Not monitored 5468A

aError¼DFR RMS values measured –RMS values calculated from short-circuit study.b% Error¼ [(DFR RMS values measured –RMS values calculated)/the smaller of the two]� 100.


length from substation X. The fault location information was then entered into the

short-circuit study to try to estimate the remaining fault resistance unknown param-

eter. At this fault location the tree fault resistance was varied until a best match was

achieved between the DFR-recorded line L1 currents and voltages and the simulation

results. A tree fault resistance of 46 primary ohms provided the best fit between

the two results. The sources from substation X are: 230-kV line L3, 230-kV line L4,

115-kV line L2, transformer T1 tertiary, and 115-kV line L5.

Since all ground currents for substation X to the fault are monitored and their RMS

values are shown in Fig. 1.16 on the right side of the DFR record, the first step will be

Fig. 1.16 Substation X DFR record for ground currents revealing the one-cycle RMS

calculation.

L1

L3

L2Substation X

230 kV

B2

B

B1

To 115 kV

XA1

B3

L5

L4

T1120 MVA

230/115/13.8 kV

C-gFault 230 kV

A2

Fig. 1.15 Substation X one-line diagram.


to confirm the accuracy of the DFR in recording the analog signals. As defined in

Section 1.10 (in pu):

InðL1Þ ¼ InðL2Þþ InðL3Þþ InðL4Þþ InðL5Þþ IterðT1ÞIbaseð115 kVÞ ¼ 100� 106ffiffiffi

3p � 115� 103

¼ 502 A


p � 230� 103¼ 251 A

Ibaseð13:8 kVÞ ¼ 100� 106

3� 13:2� 103¼ 2525:2 A

Ipu ¼ I

Ibase

ð1Þ

where I is the current recorded. Therefore, currents are

InðL1Þ ¼ 1387

251¼ 5:53 pu

InðL2Þ ¼ 772

251¼ 3:08 pu

InðL3Þ ¼ 136

251¼ 0:54 pu

InðL4Þ ¼ 134

251¼ 0:53 pu

InðL5Þ ¼ 404

502¼ 0:80 pu

IterðT2Þ ¼ 1741

2525:2¼ 0:67 pu

Substituting these values in equation (1) gives us

RHS¼ 5:53 pu

LHS ¼ 3:08þ 0:54þ 0:53þ 0:80þ 0:67 ¼ 5:62 pu

% error ¼ LHS�RHS


¼ 5:62�5:53

5:53� 100 ¼ 1:6% < 10% O:K:

It can then be concluded that the DFR accuracy of analog signal recording is

acceptable.


The model can now be verified similar to Case study 1.4 using the DFR measured

values shown in Fig. 1.16 and the RMS values calculated from the short-circuit study

simulation one-line output diagram shown in Fig. 1.17. Table 1.4 summarizes the

analysis results.

It can be concluded that this is a difficult case to match.When contribution errors are

calculated as defined in formula (2), the errors exceed the safe threshold of 10%.

However, when the errors are normalized, as in formula (3), to the total calculated short-

circuit value of 1337A, the errors are below 10%. In addition, when the normalized

errors of the feeders as defined in footnote b are added, 6.6� 1.9� 1.95 þ 1.4¼ 4.15%

which is very close to the normalized error of the total current of 3.8%.

160 A

161 A 350 A

Substation X

230 kV Bus

XC-g fault 1337 A

684 A359 A

115 kV

13.8 kV

13.8 kV

L1

L3

L2

L4

R =46 Ohms

Fig. 1.17 Short-circuit simulationresults forahigh-resistance230-kVL-g faulton the lineL1

fault location point.

T A B L E 1.4 Comparison Between Measured and Calculated Fault Currents

Feeders

Contributing to

the Bus Fault

DFR RMS

Values Measured

RMS Values

Calculated from

the Short-Circuit

Study

Error

Values

Percent

ErroraPercent

Errorb

L1-In 1387A 1337A 50A 3.8 3.8

L2-In 772A 684A 88A 12.9 6.6

L3-In 136A 161A �25A �18.4 �1.9

L4-In 134A 160A �26A �19.4 �1.95

L5-In 404A 359A 45A 12.5 3.4

T1-Ipol 1741A Not given

L5-In þ T1-Ipol Not monitoredc; can be

calculated as 369A

350A 19A 5.4 1.4

a% Error ¼ DFR RMS values measured – RMS values calculated)/the smaller of the two.b% Error ¼ DFR RMS values measured – RMS values calculated)/total current calculated.cCan be calculated from the DFR-recorded traces of L5-In and T1-Ipol:

L5-InþT1-Ipol¼ 404

502þ 1741

2525:2¼ 0:8þ 0:67 ¼ 1:47 pu

¼ 1:47� Ibase ¼ 1:47� 251 ¼ 369 A


This case study illustrates that it is very difficult to confirm power system short-

circuit models for high-resistance ground faults, and that if verification is required,

several definitions of normalized errors should be employed to get a feeling for

maximum errors.

1.14 COMTRADE STANDARD

The IEEE Standard C37.111 defines a common format for transient data

exchange (COMTRADE) for power systems, which was developed to provide a

standard file format for sampled analog wave forms and event data collected by a

variety of monitoring equipment. The COMTRADE standard format is not a

communication protocol for transferring data files, but it enables the exchange

of data files between varieties of incompatible devices. The standard can link

incompatible devices for the purpose of interchanging fault records and relay

testing data. Playing back fault events with the help of the COMTRADE standard

can flag equipment problems, hidden failures, and relay setting errors. The

availability of COMTRADE format and fault record playback capability is a

valuable tool in troubleshooting and assessing undesired operations. The system

restoration phase following undesired operations can be enhanced and performed

faster by using these tools.

Computer-based test equipment in conjunction with the COMTRADE file

format can help in recreating specific system disturbances for testing and deve-

loping new relay products. In addition, fault events that present a challenge to

existing relaying systems can be applied, using the COMTRADE standard as a

benchmark to select and approve new numerical relaying systems supplied by

various manufacturers.

Case Study 8.1 describes an application for the COMTRADE format where an

incident was triggered by a switching transient that was recorded by a DFR. The

COMTRADE format of the record was transferred to computer-based test equip-

ment. The DFR device and test equipment were manufactured by two different

companies. The transient activated an undesired breaker failure operation, which

resulted in the tripping of a 150-MW combined-cycle plant. Analysis of the DFR

records did not reveal a fault, and therefore the plant was returned to service

postulating incorrect operation of a 138-kV breaker failure relay. To analyze the

incident further, the DFR record for the incident was first converted to COMTRADE

format and then played back to test the breaker failure relay, after its isolation, using

an automated test set. The playback confirmed that the breaker failure relay

produced a consistent output and that the output was present only when the dc

power was switched on, energizing the relay. The playback testing led to a review of

the schematic and wiring drawings and the discovery of a welded contact in one of

the breaker failure initiation auxiliary relays.

COMTRADE STANDARD 31

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